IR 05000352/1989019
| ML19332G015 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 12/12/1989 |
| From: | Doerflein L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19332G014 | List: |
| References | |
| TASK-2.B.2, TASK-2.B.3, TASK-TM 50-352-89-19, 50-353-89-28, NUDOCS 8912200037 | |
| Download: ML19332G015 (62) | |
Text
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REGION I
' ' Report No.. 89-19 ' 89-28 i
! . Docket No.
50-352
50-353 i License No.- NPF-39 , ! NPF-85 Lisensee: Philadelphia Electric Company Correspondence Control Desk P.O. Box 7520 Philadelphia, Pa 19101 ' Facility Name: Limerick Generating Station, Units I and 2 Inspection Period: September 12, 1989 - October 10, 1989 Inspectors: T. J. Kenny, Senior Resident Inspector L. L. Scholl, Resident Inspector M. G. Evans, Resident Inspector . II!Il fi f
Approved-by: Quyhu Lawrence T. Doerflein, Chief Date' Reactor Projects Sectiorf 2B - Summary: Routine daytime (199 hours) and backshift/ holiday (47 hours) inspections by the resident inspectors consisting of (a) plant tours, (b) observations of maintenance and surveillance testing, (c) review of LERs and periodic reports, (d) review of operational events, (e) system walkdowns, and , (f) observation and results review of power ascension activities on Unit 2.
" Results: l Unit 1 Operated with no reportable events during this report period.
' ' The licensee responded appropriately to an anonymous call concerning a security threat.
However, no threat to the site was identified.
(see Section 2.1.1) l l Unit 2 The startup test program progressed on schedule with no major > l problems. One self identified violation was documented for
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entering an operating condition prior to meeting a Technical , Specification Limiting Condition for Operation (see Section . ' I t 2.2.1 for details).
Common An allegation was closed regarding purity of weld gas in the
application of stainless steel welding (Section 9.0). Meetings . with the licensee involving Nuclear Engineering self evaluation and Power Ascension self-assessment are documented in Section 10 Attachment'A: List of attendees and handout for the September 27, 1989, NRC-PECo meeting.
Attachment B: List of attendees and handout for the October 6,1989, NRC-PEco meeting.
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. ! , . DETAILS 1.0 Persons Contacted Within this report period, interviews and discussions were conducted with members of licensee management and staff as necessary to support inspection activity.
2.0 Operational Safety Verification . The inspectors conducted routine entries into the protected areas of the , plant, including the control room, reactor enclosure, fuel floor, and drywell (when access is possible).
During the inspection, discussions , were held with operators, technicians (HP & I&C), mechanics, security < personnel, supervisors and plant management.
The inspections were conducted in accordance with hRC Inspection Procedure 71707 and affirmed the licensee's commitments and compliance with 10 CFR, Technical Specifications, License Conditions and Administrative Procedures.
2.1 Unit 1 (71707, 93702) 2.1.1 Inspector Comment and Findings ' Unit 1 maintained 100% reactor power throughout the inspection period with the exception of occassional load drops to perform control rod pattern adjustments.
On September 11, 1989, at 11:37 a.m. the switchboard operator at the licensee's corporate office (23rd and Market Streets, Philadelphia) received an anonymous telephone call threat to site security. Although the licensee could not assrc* ate this threat with any previous thre?t to the Limerick Stat)on, the licensee implemented precauuonary measures and instituted a heightened security awareness program. The inspector found the actions appropriate and in accordance with the site plan. No threats to the site were identified during the heightened awareness.
2.2 Unit 2 (71707, 93702) 2.2.1 Inspector Comments and Findings ' This report period began with Unit 2 at 28% reactor power, and Test Condition 2 (25-45% power) Power Ascension testing ongoing.
, On September 18, 1989, the " Loss of Offsite Power" test was
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successfully completed and the reactor was returned to power on September 20, 1989. On September 26, 1989, a 12-day mini-outage was started following successful completion of the " Shutdown from Outside the Control Room" test on September 25, 1989. Major activities conducted during the outage included condenser inspections and repair, and local leak rate testing. Outage work was completed and the unit achieved criticality on October 8, 1989. At the end of the report period the unit was at 15% power and increasing in preparation for_ Test Condition 3 testing at 45-75% reactor power.
(Power Ascension Test Activities are discussed in Section 6.0).
On September 18, 1989, during the cooldown following the " Loss of Offsite Site Power test, the licensee identified that the bottom head temperatures and pressures, as measured by the bottom head drain line temperature element, exceeded the heatup-cooldown (Curve B) limits of the pressure - temperature (P-T) curve, figure 3,4.6.1-1 in the Technical Specifications. The maximum amount the..urve was exceeded was less than 50 psig.. Technical Specification 3.4.6 requires that if any of the above limits are exceeded, temperature and/or. pressure be restored to-within the limits within 30 minutes; an engineering evaluation be performed to determine the effects of the out-of-limit condition on the structural integrity of the reactor :oolant system; and a determination that the reactor coolant system remains acceptable for continued operations or be in at least HOT SHUTDOWN within 12 hours and COLD SHUTDOWN within the following 24 hours.
The plant was already in hot shutdown and pressure was restored to within the limits.
The licensee performed an engineering evaluation which indicated that curve B of figure 3.4.6.1-1 applies to the feedwater nozzle region of the vessel and was developed to bound the brittle fracture requirements of 10 CFR 50 Appendix G for all regions in the vessel.
Thermocouple data f3m the event showed that while bottom head temperatures were w the left of curve B, the minimum recirculation loop temperature was 340'F, and the minimum feedwater nozzle region temperature was 436'F. The temperatures were well above the allowable minimums for the - regions delineated above. As for the bottom head region, curve B is somewhat conservative and the spucific limits for that region were not exceeded.
All safety margins prescribed in 10 CFR 50 Appendix G or ASME l Code Appendix G were maintained during the cooldown. The results of the engineering evaluation determined that no safety L l' - ,
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Therefore, the reactor coolant system was acceptable for continued operation.
The inspector had no further questions concerning the engineering evaluation and analysis.
' , [. On September 20, 1989, at 3:15 p.m., while preparations were ' being completed for the restart of the Unit, the reactor mode l switch was moved from the ' shutdown' to the 'startup' position prior to realigning the Residual Heat Removal (RHR) system from the Shutdown Cooling Mode of operation. Technical Specification (TS) 3.5.1.b Limiting Condition for Operation (LCO) requires subsystems of the low pressure coolant injectior (LPCI) system of the RHR system be operable prior to entering operational condition (Opcon) 2 (startup). TS 3.0.4 requires that entry into an operational condition shall not be made when the conditions for the LCO are not met. Therefore, the licensee failed to comply with TS 3.0.4 by entering Opcon 2 prior to , restoring the RHR lineup to the LpCI mode of operation. This is a licensee identified violation (NCV 50-353/89-28-01). The RHR lineup was restored at 3:30 p.m., and the LPCI subsystem was de:lared operable at 6:23 p.m.
The apparent cause of the violation was the operators failure to explicitly fol' low GP-2, " Normal' Plant Startup," by not completing step 3.2.11. "RHR Shutdown from shutdown cooling mode" prior to step 3.3.11 " permission to change opcons".
In addition GP-2 did not require that procedural steps be completed in numerical sequence.
Licensee management took prompt corrective action including revising GP-2 by placing an asterisk by each step required to be completed prior to a mode change and adding an additional step requiring that all asterisk steps be completed prior to changing mode switch position. Although this is a violation, in accordance with the provisions of 10 CFR Part 2 Appendix C, Section V.G.1, a violation will not be issued and.
, no reply by the licensee is necessary.
! On September 22 during the performance of an Emergen:y Service Water (ESW) flow verification test on 'B' loop of ESW, return - vcive 11-2067 was found out of position. This valve isolates the 'O' loop of ESW return from '2B' & '2H' core spray room unit coolers, High Pressure Coolant Injection (HPCI) pump room unit l cooler, and RHR room unit coolers and associated seal coolers and l motor oil coolers. This valve is located within close proximity to valve 11-2013 which is frequently closed to isolate service water supply to ESW.
Valve 11-2067 apparently was inadvertently l closed during this evolution. Valve lineup verifications were performed for both the 'A' and 'B' loops of ESW with no other ... - - - - - .
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i valve position problems identified. Operator error appears to be the likely cause of the occurrence. The licensee is con-i tinuing to investigate how the valve was shut and for how long.
The inspectors will further review the results of the licensee's root cause analysis and adequacy of corrective action upon receipt of the Licensee Event Report, f 2.2.2 Engineered Safety Feature (ESF) System Walkdown (7171_0j The inspectors verified the oper6bility of portions of the 2A Emergency Diesel Generator System by performing.a walkdown of the system to confirm that system lineup procedures agree with plant drawings and the as-built configuration. This ESF system , walkdown was also conducted to identify equipment conditions that might degrade performance, to determine that in.,trumentation is calibrated and functioning, and to verify that valves are . properly positioned and locked as appropriate.
The inspectors also utilized rrethods prescribed in a study prepared for the NRC by Brookhaven National Laboratory using the Limerick Probabi-listic Risk Assessment (PRA), to enhance the inspection activity.
The study, entitled PRA-Based System Inspection Plan, dated May 1986, provides inspection guidance by prioritizing plant safety systems with respect to their importance to risk. An abbreviated system checklist in Table 1-4, which identifies components that are considered to have a high contribution to risk as determined in the PRA, was also used by the inspector.
The following procedures, drswings and tests were reviewed during this inspection: Drawing M-11 Emergency Service Water Piping and , Instrumentation Drawing Drawing M-20 Fuel and Diesel Oil Storage & Transfer (Diesel Generator "A", Unit 2) 2592.1,N (Col. 1) Equipment Alignment for 2A Diesel Generator Operation S92.1.N Diesel Generator Set Up for Antnmatic . Operation f FSAR 9.5.4 Diesel Generator Fuel Oil System FSAR 9. 5.!, Diesel Generator Cooling Water System FSAR 9.5.6 Diesel Generator Starting System
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. FSAR 9.5.7 Diesel Generator Lubrication System FSAR 9.5.8 Diesel Generator Combustion Air Intake ' and Exhaust System This inspection was ongoing at the end of this report period.
No discrepancies or problems have been identified thus far.
. The inspection will continue and the results will be reported in NRC inspection report 50-353/89-30,
2.2.3 Reactor Coolant System Leakage Detection Systems ' . On September 14, 1989, during a tour of the control room, the inspector noted that the Unit 2 drywell air cooler condensate flow indication was 3.0 gallons per minute (gpm). After passing through the flow instrument the condensate passes to the floor drain collection systems. The floor drain flow monitoring - system indicated a flow of 0.2 gpm.
Since the air cooler condensate flow contributes to floor drain flow, the floor drain system should indicate higher flow than air cooler flow.
These indications were discussed with the instrument and controls department personnel who investigated the reason for the discrepancy. The results of the investigation determined that the air cooler condensate flow detector had become fouled and required cleaning. All of the flow detectors have since been flushed, during a maintenance outage, and the readings returned i to the actual flow condition.
The instrument alarm setpoint is , normally set conservatively such that if one of the instruments becomes inoperable the technical specification requirements are
still met.
The inspector had no further questions regarding , this event.
3.0 Update /Closcout of Open Items (92701, 92702) 3.1 Unit _1 3.1.1 (Closed) Violation 50-352/89-12-01, Inadequate Radiation , Monitor Calibratior: This violation identified an inadequate surveillance test whose purpose was to perform periodic calibration of the Primary Containment Post-LOCA H!gh Range Radiation Monitors.
Contrary te the requirements of Technical Specification 3.3.75, the procedure did not.cortain an electronic calibration of the channel for decade ranges above 10 rem per hour.
The licensee declared the teonitors inoperable and immediately revised the , j >
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g procedure and performed a proper calibration. The cause was determined to be misinterpretation of vendor information by the , writer of the surveillance test.
This error was reviewed for its potential impact on other procedures and was found to be isolated to these specific monitors. The inspector reviewed the revised ST-2-026-407-1 and verified it now performs calibrations up'to 1 x 10' Rem per hour and meets the requirements of Technical Specifications.
> The inspector found the licensee actions adequate and considers this item closed.
3.1.2 (Closed) Violation 50-352/89-12-03, InoperaDie Scram Accumulators On six occasions between September 11, 1984 and May 9, 1989, numerous hydraulic control unit scram accumulators failed to hold pressure for ten minutes during surveillance testing and the licensee failed to declare them inoperable and take the action required by Technical Specification (TS) 3.1.3.5.
The cause of the violation was an incorrect interpretation of the intent of the TS by the licensee. The licensee intended to use the test results for predictive maintenance purposes instead of for making operability determinations which is the actual purpose of the test.
When the deficiency was identified the licensee requested and was granted a waiver of compliance to the TS to permit continued plant operation with the c'egraded accumulator check valves.
This was based on the fact that the accumulators are not required to scram the control rods if reactor pressure is greater than 600 psig.
The waiver of compliance was followed by an emergency TS change to clarify the plant conditions for . " periods when the accumulators must be operable (i.e. when reactor pressure is less than 600 psig).
The licensee committed to repair the affected accumulators prior to the next Unit 1 plant startup.
All of the Unit 2 accumulators were satisfactorily tested prior to initial criticality.
The inspector reviewed the revised surveillance test ST-3-047-790-1, CRD Accumulator Check Valve Timing Test, - which now contains an additional requirement to have the test result * evaluated by the plant Reactor Engineer and to initiate maintenance on failed accumulators.
This TS misinterpretation appears to be an isolated case and is not indicative of a programmatic problem.
Tie inspector found the licensee's actions adequate and considers this item closed.
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3.1.3 (Closed) Violation 50-352/89-12-02, Failure to Follow Health Physics procedures Two examples of failure to folluw health physics procedures were identified. One involved the use of high efficiency particulate , air (HEPA) filter ventilation units and the other was a failure of a health physics technician to follow the requitements of a radiological work permit (RWP).
The corrective actions for these specific violations were reviewed and found to be adequate; however, the inspectors had noted that these two violations closely followed several other instances of procedural non-compliance by other work groups.
Based on this the inspectors . discussed their concern with station management that procedural noncompliance appears to be a potential programmatic problem, not just isolated occurrences.
The licensee management acknow-ledged this concern and implemented measures to reduce the number of personnel errors.
The following actions were taken: procedural compliance has been emphasized through training - to plant supervisory personnel along with management's concern about the apparent increasing frequency of occurrences; l discussions were held within each plant group concerning - - the need for compliance with procedures and possible consequences of non-compliance both to plant operations and personnel safety; procedure compliance is emphasized in both initial and - requalification General Employee Training (GET) classes; the plant manager issued e letter to all station personnel - emphasizing that forethought and planning of work must be included in performance of normal work activities; and a revised method of scheduling daily work activities was - implemented to regulate activities such that the number and scope of planned activities is consistent with the available staffing.
The inspector concluded these acticns have been effective in reducing the number of personnel errors including a reduction in the frequency of procedure non-compliance occurrences.
The inspector had no further questions and considers this item closed, i
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. 3.2 Unit 2 i 3.2.1 (Closed) TMI Action Plan Item 11.8.3, Post Accident Sampling System (PASS) The Unit 2 PASS is identical to Unit 1.
The system has been installed and successfully tested during the preoperational test ' phase. The NRC acceptance of the PASS design is documented in , the Limerick Safety Evaluation Report and Supplements 2 and 4.
, The following routine tests have also been satisfactorily performed by the plant staff to verify system operability: RT-5-030-573-2, "Routir.e Secondary Containment Atmosphere - Sampling From PASS;" RT-5-030-574-2, " Routine Drywell Atmosphere Sampling From - PASS;" RT-5-030-575-2, " Routine Suppression Pool Atmosphere - Sampling From PASS;" RT-5-030-576-2, " Routine Jet Pump Small Volame Liquid - Sampling From PASS;" , RT-5-030-577-2, " Routine RHR Small Volume Liquid Sampling - From PASS;" RT-5-030-578-2, " Routine Jet Pump Large Volume Liquid - Sampling From PASS;" and RT-5-030-579-2, " Routine RHR Large Volume Liquid Sampling - From PASS."
The inspector also performed a walkdown of the major system components and found them to be in good condition.
The system ' status was also reviewed with the licensee system engineer.
The inspector had no further questions and considers this item closed.
3.2.2 (Closed) TMI Action Plan Item II.B.2, Plant Shielding . The licensee performed a design review of the plant shielding to allow access to the plant areas after an accident.
Areas and safety-related equipment vital for post-accident occupancy or operation were identified, and post-accident deses were calculated.
No additional shielding was determined to be required.
Two potential problem areas were identified in that , e
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l , the pathways for (1) Main Control Room to PAS $ and Radwaste , Enclosure Vital areas and (2) Radwaste Enclosure Elevation 217 feet to North Stack Instrument Room were determined to have high ! dose rates at certain times after the accident. Alternate ' t pathways have been identified by the licensee.
The licensee's design review was determined to be adequate as documented in the , Limerick Safety Evaluation Report, August 1983.
The inspector , ! reviewed the following procedures to assure that the appropriate
pathways would be utilized following an accident:
Emergency Plan Implementing Procedure, EP-250, " Personnel - i Safety Team," Revision 5; i EP-251, " Plant Survey Group," R"ision 4; and - Health Physics Procedure, HP-310, " Radiation Work Permits," - > Revision 16.
The inspector noted that procedures for determining the route - to the work sites following an accident were in place.
The inspector had no further question 4 and considers this item closed, t 4.0 Surveillance /Special Test Observations (61726) During this inspection perico, the inspector reviewed in progress surveillance testing as well as completed surveillance packages.
The inspector verified that surveillances were performed in accordance with licensee approved procedures, plant technical specifications, and NRC Regulatory Requirements.
The inspector also verified that instruments used were within calibration tolerances and that qualified technicians performed the surveillances. The following surveillance tests were observed: Unit 1 ST-6-107-590-2, " Daily Surveillance Logs /Opcons 1, 2, 3" $T-6-011-232-0, "B Loop ESW Pump, Valve, and Flow Test" 5.0 Maintenance Observations (62703) > The inspector reviewed the safety related maintenance activities listed below to verify that repairs were made in accordance with approved procedures, and-in compliance with NRC regulations and recognized codes and standards. The inspector also verified that the replacement parts and quality control utilized on the repairs were in compliance with the licensee's QA program.
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1 l Unit 1 - September 14, 1989 Drywell Air Cooler Condensate Flow Instrumentation Troubleshooting - MRF 8902651 012 Emergency Diesel Generator Diode Replacement
i Unit 2 i - MRF 8909025 HV 52 2F006B Valve Repairs j 6.0 Power Ascension Test Program (PATP) Unit 2 (72300, 72301, 72302, 72400, 7755b,7f516,72532) 6.1 Overall Power Ascension Test Program At the beginning of this report period Test Conoition (TC) 2 (approximately 25-45% power) testing was in progress. Major test evolutions conducted were the Loss of Turbine Generator and Offsite Power lest on September 18, 1989 and the Shutdown from Outside the Control Room Test cn September 25, 1989.
Following the shutdown on September 25, a mini-outage was conducted. TC 3 (approximately 45-75% power) was entered on October 6, 1989 and at the end of the ' inspection period TC 3 testing was ongoing.
6.2 Power Ascension Testing Activities The inspectors witnessed portions of the power ascension testing activities discussed below. The performance of these tests were witnessed to verify the attributes previously identified in Inspection Report No. 50-353/89-24, Section 4.3.
2STP-26.2, Relief Valve Rated Pressure Test On September 15, 1989 the inspector witnessed safety relief valve (SRV) testing conducted per 2STP-26.2. The inspector witnessed the test briefing and noted its adequacy. The test director thoroughly reviewed the test acceptance criteria and cautions and coordinated how the test would be conducted. All 14 SRVs opened and closed when actuated.
During testing of SRV "M", the associated acoustic monitor was determined to be inoperative.
A 48 hour LCO was entered.
Troubleshooting followed and the acoustic monitor was returned to operable status within 48 hours.
2STP-27.1, Turbine Trip Within Bypass Valve Capac_ity l On September 18, 1989 the inspector witnessed the successful testing l l - L
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of the Turbine Trip with Bypass Valve Capacity. The inspector noted that reactor level and pressure remained stable during the test.
2STP-28.1, Reactor Shutdown to Hot Standby Demonstration On September 25, 1989 at 6:00 p.m. the inspectors witnessed 2STP-28.1, " Unit Shutdown to Hot Standby Demonstration." The Unit was tripped off the line by inserting a false high radiation signal into the control circuitry which closed the Main Steam isolation valves which in turn tripped the reactor. The operators then utilized modified existing procedures to prove control of reactor pressure and level from outside the control room. The ability to cool the suppression pool and the reactor system was also demonstrated.
The inspector noted the testing was conducted in accordance with approved procedures and was successful.
2STp-28.2, Reactor Cooldown Demonstration On September 26, 1989 the inspectors witnessed the demonstration of a reactor cooldown from outside the main control room. The shutdown cooling mode of the residual heat removal system was operated from the remote shutdown panel to reduce the reactor coolant temperature 50*F without exceeding the Technical Specification cooldown limits.
The inspector noted the test was successful.
2STP-31.1, Loss of Turbine Generator and Offsite Power On September 19, 1989 the inspectors witnessed the operatMg crew, designated to perform the loss of offsite power test, pe~ y m training for the test at the simulator.
The crew discus u d the outcome of the test then walked through the test proceddre and the outcome of the results of losing offsite power. The crew performed the test on the simulator three times, each time conducting a critique to assess the results. At 7:05 p.m. the same date the inspectors witnessed the actual loss of offsite power test, 2STP-31.1, " Loss of ' Turbine Generator and Offsite Power" and the recovery from same, SP.094, " Recovery from the Loss of Off site Power Test 2STP-31.1".
The plant performed predictably with a reactor scram occurring 49 seconds after the loss of power due to low level in the reactor vessel. All other systems functioned normally including the fast start and loading of all four diesel generators.
However, following this test during the reactor cooldown, the Nil Ductility Temperature (NDT) l curve from the Technical Specifications was exceeded.
This was
discussed in Section 2.2.1.
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3 6.3 Power Power Ascension Test Results Evaluation The startup tests listed below were reviewed for the attributes identified in inspection report 50-353/89-24, Section 4.4.
Except as noted below, all startup test results were found to meet the . attributes referenced above. A summary of each startup test follows.
. 6.3.1 Test Condition 2 ' 2STP-1.2, " Chemistry Data." results approved September 27, 1989 l Test Exception Report (TER) 122 was written to document a level 2 test acceptance criterion for failure of the dissolved oxygen concentration to be within the limits of > 20 ppb and . < 200 ppb.
The actual value was 10 ppb.
This is a General
Electric (GE) Water Ouality Specification limit.
The TER will > remain open pending the installation of a feedwater oxygen injection system. All other acceptance criteria were satisfied.
2STP-1.6, " Sample Station Operability," results approved I september 28, 1989 i ~ The operability of the sample points for Residual Heat Removal (RHR) A and B heat exchanger outlets was satisfactorily > demonstrated.
, 2STP-2.1, " Radiation Surveys," results approved September 18,19 F All acceptan:e criteria were satisfied.
2STP-5.8, " Scram Timing of Selected Rods During Planned Scrams of the Startup Test Program," results approved September 27, 1989 This test was performed twice during TC 2.
First during the Loss of Turbine Generator and Offsite Power Test (2STP-31.1) on September 18, 1989 and again dying the Shutdown from Outside the Control Room Test (2STP-28.1) on September 25, 1989.
The four control rods for which scram times were monitored during l the tests were 02-43, 22-11, 26-23, and 58-43. All scram times were well within the acceptance criteria of < 7.0 seconds.
2STP-9.1, " Reference Leg Temperature Comparison," results approved September 8, 1989 The narrow range and wide range level indicators were verified to give consistent response.
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, 2STP-14.5, " Stability Check _ Condensate Storage Tank (CST) to heactor Pressure Vessel (RPV) at 150 psig," results approved September 28, 1989 l The test was satisfactorily completed with the exception of the + 60 gpm step changes for Reactor Core Isolation Cooling (RCIC) T1ow at 300 gpm because the RCIC turbine speed would have gone below the limit of 2050 rpm.
In addition, the 600 gpm + 60 gpm step change was not completed because the reactor water level r was at 60 inches and increasing. A TER was written because all Level 2 acceptance criteria could not be satisfied without completion of these RCIC runs.
The TER was analyzed by GE San Jose and accepted as is because the purpose of the tests was to confirm that the RCIC turbine control system was a damped stable system.
This was oreviously demonstrated in Startup Tests 2STP-14.1, 14.2 and 14.4 and the RCIC controller settings have not been changed since performance of those tests.
The inspector reviewed the analysis and found it to be acceptable.
2STP-14.6, "RCIC Cold Quick Start at Rated Pressure CST to.
hPV " results approved September 0,1989 All acceptance criteria were satisfied with the exception of the decay ratio for RCIC system flow being greater than.25 after achieving rated flow to the vessel.
This was also the case when this test was conducted during TC 1.
As in TC 1, the decay ratio was evaluated and accepted as is based on upon flow disturbances not being a function of the control system components. The inspector found the evaluation to be adequate.
2STP-14.7, "RCIC Surveillance Tests CST to CST at Rated Pressure," results approved September 19, 1939 All acceptance criteria were satisfied.
RCIC reached rated flow of 600 gpm in 16.6 seconds.
2STP-14.8, "RCIC Endurance Run," results approved September 8, 1989 All acceptance criteria for the RCIC endurance run were satisfied.
2STP-14.9, " Loss of AC Power," results approved September 19, 1989 All acceptance criteria were satisfied.
RCIC was successfully run for two hours with all AC powered components of the RCIC l system made inoperative.
RCIC was then successfully quick L started and shutdown two additional times in the vessel injection mode.
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2STP-19.1, "BUCLE Calculation," results approved September 7, 1989 This test was conducted under TC 1 test conditions, but the results were not evaluated until TC 2.
The off line computer program BUCLE was used to calculate the core thermal limits at - reactor power of 15% and core flow of 42.32 mlb/hr. All acceptance criteria were satisfied.
2STP-19.2, " Process Computer Calculation," results approved September 20, 1989 Verification of core thermal-hydraulic limits was performed at 38.7% of rated thermal power and core flow of 45.27 mlb/hr.
All acceptance criteria were satisfied.
2STP-22.1, " Pressure Regulator Response - Control Valve Operation," results approved September 22, 1989 All acceptance criteria were satisfied.
The inspector noted discrepancies in the analysis section of the procedure.
Several, steps were listed as not applicable for TC 2.
However, steps applicable in subsequent test conditions (i.e. TC 5) required TC 2 data from the steps which were not applicable in TC 2.
The inspector discussed this with a licensee representative who stated that the discrepancies had been noted and that the data was not actually required for subsequent test conditions.
The licensee also stated that this procedure and 2STP-22.3 were being revised.
The inspector reviewed the draft revision and had no further questions.
2STP-22.3, " Pressure Regulator Response Bypass Valve Operation," results approved September 22, 1989 All acceptance criteria were satisfied.
2STP-23.3, "feedwater System level Setpoint Changes," results approved September 26, 1989 All acceptance criteria were satisfied.
The feedwater system adequately responded to the + 5 inch level setpoint changes.
2STP-26.2, " Relief Valve Rated Pressure Test," results approved September 22, 1989 Four TERs were written to document the following problems: (1) two safety relief valves (SRVs) failed to have their tailpipe .
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temperatures return to within 10*F of the initial reading (Level 2 acceptance criteria), (2) during the test, SRVs were not , opened long enough to obtain steady state data and analyze decay ratios (Level 2 acceptance criteria), (3) relief valve , PSV41-2F013M did not indicate open when the valve was actually ' open as indicated by a drop in generator MWe, and (4) tailpipe temperature indication for relief valve PSV41-2F013L was determined to be invalid since the peak temperature during testing.was 140'F versus 300-350'F for the other SRVs. The first two TERs were evaluated by GE San Jose and determined te be acceptable as is. The inspector reviewed the evaluations and found them to be adequate.
For the third TER, the acoustic monitor was repaired and the valve was retested per Hot Functional (HF)-008, " Acoustic Monitor Test." The fourth TER remains open pending temperature indicator troubleshooting and subsequent retesting.
2STP-27.1, " Turbine Trip Within Bypass Valve Capacity," results approved September 27,1989 All acceptance criteria were satisfied.
At 21% power the turbine was tripped and the reactor did not scram. One TER was generated to document problems with several Plant Monitoring System (PMS) data points being inconsistent.
In addition, Bypass valve (BPV) #5 indicated 70% open in the control room and on PMS traces. However BPV #6 was fully open.
Status of BPV #5 is being investigated. MRF's were written to investigate the above problems.
The TER remains open to track resolution of the problems.
2STP-28.1, " Reactor Shutdown to Hot Standby Demonstration," results approved September 27, 1989 All acceptance criteria were satisfied. The reactor was safely shutdown to the Hot Standby condition from outside the control room.
Following the scram, the reactor was stabilized at a pres:,ure of 795 psig, saturation temperature of 519'F and level of 43 inches. A controlled depressurization/cooldown was performed for a half hour to a pressure of 750 psig, temperature of 513 F and level of 33 inches.
2STP-28.2, " Reactor Cooldown Demonstration," results approved September 28, 1989 The ability to cool the reactor down from hot to cold shutdown from outside the control room was adequately demonstrated. A'i l acceptance criteria were satisfied.
.
i l . '* i , ..
t_ ! 2STP-30.3, " Recirculation System Performance," results approved i September 18, 1989 Various reactor recirculation system parameters were recorded to obtain data at approximately 24% thermal power. There were no acceptance criteria or analysis performed at this TC.
2STP-31.1, " Loss of Turbine Generator and Offsite Power," l results approved September 27, 1989
The inspector reviewed the results including review of time history plots and verified that all safety systems performed their intended function without manual assistance.
Minimum water level was -30.7 inches and maximum reactor pressure was
925 psig, well within the acceptance criteria of -129 inches and 1250 psig.
All acceptance criteria were satisfied.
2STP-33.1, " Main Steam Piping (Inside Drywell) Steady State Vibration," results approved August 22, 1989 i Two Level 1 and three Level 2 acceptuce criteria failures occurred for main steam line piping exceeding allowable and expected values for vibration at certain points.
A TER was written to document the failures and GE San Jose analyzed them.
Since the values did not exceed the transient allowable dis-placement criteria and were well within code limits for pipe stresses, the values were accepted as is and GE Field Deviation Disposition Request (FDDR) No. HH2-5047, Rev 0 was approved revising the Level 1 and Level 2 acceptance criteria for the affected data points.
All other acceptance criteria were satisfied.
The inspector reviewed the analysis and found it to , be adequate.
2STP-33.3, " Main Steam Piping (Outside Drywell) Main Steam bypass and Feedwater Piping Steady State Vibration," results approved September 12, and 22, 1989 All acceptance criteria were satisfied.
Signals from several accelerometers were determined to be invalid because the accelerometers needed to be repaired and/or replaced. These points were analyzed and a thorough walkdown was performed for the piping in the vicinity of the affected accelerometers. No damage or interferences to piping, supports, or insulation were i noted. The resolution was to repair or replace the accelerometers l and obtain the data at the next plateau. The inspector reviewed the analysis and had no further question e a . ,
19 < , 2STP-33.7, "RHR Shutdown Cooling Mode Piping Steady State Vibration," results approved September 28, 1989 ) Acceptance criteria were satisfied. As in 25TP-33.3, values for several accelerometers were determined to be invalid.
Analysis i' was conducted and the resolution was to accept the results as is. The inspector reviewed the analysis and had no questions.. 2STP-33.8, "EHC System Piping Steady State Vibration," results approved September 8, 1989 All acceptance criteria were satisfied.
2STP-36.1,." Main Steam Piping Vibration during Main Stop Valve and Control Valve Closures," results approved September 27, 1989 This test was conducted during 2STP-27.1, " Turbine Trip within Bypsss. Valve Capacity." TER 114 documented the level 2 acceptance criteria failure for the maximum load at a certain point exceeding the cceptance limits.
Plant Staff Field Report (PSFR) #645 documents the engineering review and analysis of the failure.
The resolution was to accept the results as is and perform further monitoring at a subsequent plateau.
The - inspector reviewed the analysis and found it to be adequate.
2STP-36.2, " Main Steam Relief Valve Discharge Piping Vibration ' During SRV Operation," results approved Seytember 28, 1989 This test was conducted during 2STP-26.2, " Relief Valve Rated Pressure Test." All acceptance criteria were satisfied.
2STP-99.4, " Test Plateau B - Test Condition 2," results approved September 28, 1989 The inspector reviewed this procedure to ensure that all planned testing for TC-2 had been completed and that all Test Exception
Reports remaining open enuld safely be carried forward into ! subsequent test conditions.
Fifteen TERs remained open at the l end of TC-2.
The inspector reviewed the TERs and found that five of the fiteen TERs had subsequently been satisfactorily closed and that the remaining ten TERs could remain open into future test conditions. Three tests involving SRM/IRM overlap, HPCI system testing, and selected BOP pipe displacements were not performed during TC-2 because plant conditions did not allow l testing.
These tests have been administratively moved to TC- +
- ,
, ,
In addition, two RCIC 2STP-14.3 "RCIC Stability Check at 150 psig" and 2STO-14.7, "RCIC Surveillance to CST (150 psig), were deleted from TC-2 and the test program.
The tests were ' i deleted because previous testing of RCIC at 150 psig has been ' conducted and no controller setting adjustments have been made since conduct of that testing. The inspector reviewed GE Field Deviation Disposition Request (FDDR) No. HH2-4448, Revision 11, which documents the basis for the deletions and found the deletions to be appropriate.
6.4 High Pressure Coolant Injection (HpCI) System Testing In Inspection Report 50-353/89-24, Section B4.2.6, the inspector noted that HPCI testing would be conducted prior to exceeding 50% rated power. However, following further licensee evaluation of performing HPCI vessel injection at 40 to 50% power, the licensee has determined . that testing at that power level is not prudent.
Therefore, the ' licensee has proposed the first testing of HPCI injection to the vessel would take place between 65 - 75% power.
The inspe: tor discussed the proposed testing with licensee test personnel and determined that the decision was based primarily on the reactor water level transient which would result from a HPCI injection in the 40 to 50% power range.
In this power range, there are only two feedwater pumps in service supplying between 5.5 and 7 M1b/hr.
Since a HPCI injection would add an addition 5600 gpm (approximately 2 Mib/hr) of flow into the vessel, the feedwater system would have to run back to maintain reactor vessel level.
Evaluations indicate that feedwater may not be able to run back enough at this lower power to adequately compensate for the HPCI injection flow.
In this case, high reactor water level (level 8) would result in the main turbine, feedwater pumps and HPCI system tripping.
This would result in a reactor scram from the main turbine trip.
At power levels above 65%, feedwater response should be adequate to avoid a high level feedpump trip and subsequent reactor scram during HPCI injection. Above this power level, all three feedwater pumps should be in service.
The results of the Limerick 1 testing which was also initially performed at approximately 68% power showed that , reactor level control was adequate to perform the HPCI injection j testing.
l ! f Based upon the results of the licensee's evaluation, the inspector has found it appropriate to perform the first HPCI vessel injection testing in the 65 - 75% power range.
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7.0 Review of Periodic and Special Reports (90713) Upon receipt, the inspector reviewed periodic and special reports. The I review included the following: inclusion of information required by the NRC; test results and/or supporting information consistent with design predictions and performance specifications; planned corrective action for resolution of problems; and reportability and validity of report , ' information. The following periodic report was reviewed:
Monthly Operating Report - August 1989 f The inspector had no questions regarding this report.
80 Licens,ef Event Report Followup (90712)
The Sspector reviewed the-following LERs to determine that reportability requ', ements were fulfilled, that immediate corrective action was taken, ' and that corrective action to prevent recurrence was accomplished.
In accordance with the above inspection module the inspector considers the following reports closed.
The inspector had no further comments or questions except as noted.
, LER Number Subject / Comments , 1-89-034, Revision 1 This revision corrects an error in the number of valves reported to be involved in the event.
Revision 0 was previcusly reviewed in Inspection Report 50-352/89-15 and 50-353/89-24.
1-89-049 Special Report concerning diesel generator surveillance test failure due to a positive crankcase pressure indication. The cause of the failure is unknown.
The event is considered to be an isolated occurrence because no abnormalities were found during inspection or subsequent test runs of the engine.
1-89-050 * Potential Reactor Core Isolation Cooling System unavailability in a seismic / hydrodynamic event because alignment pins were not installed on the RCIC pump mounting brackets.
(NCV 352/89-19-01) 1-89-052 * Missed primary coolant and gaseous effluent sampling and radiological analyses during reactor power changes of more than 15% of RTP in one hour.
The missed sampling and analyses were caused by a procedural deficiency which led to inadequate communication between shift personnel.
(NCV 352/89-13-02)
w .. Ku, . p~ > w . - 22
1-88-042, Revision 5 This revision documents the completion of the physical separation inspections of safety-related-electrical panels.
- These reports identify conditions which are violations of the plant technical specifications. The inspectors have reviewed these events and
,- determined that they satisfy the criteria for licensee identified violations as stated in 10 CFR 2 Appendix C, Section V.G.1 and as such a notice of violation will not be issued.
' 9.0 RI-89-A-0108 Allegation Followup Involving Purity of Weld Purging Gas (93702) On September 9, 1989, the NRC received an anonymous allegation concerning the transfer of Argon (a purge gas used to weld stainless steel) from large storage containers to smaller ones for use in the field.
The < alleger thought this tc be a bad practice.
Based on the information received, Region I asked the licensee to conduct an investigation into the alleged practice.
The results of the licensee's investigation are described below.
A Non "Q" major modification (6077-0) designed to increase the capacity of the solid radwaste facility by changing external processing station piping from:1" diameter to 1-1/2" diameter was being installed. Work was initiated on Thursday, September 7, 1989, and began with 1-1/2" diametcr half-coupling additions.
During the -staging of work, Site Services craftsmen determined that the use of a small argon bottle would provide a safer practf ce-than carrying:a standard gas bottle down the stairs to Elcyation 162'in the Radwaste Facility.
.Due to the uneva11 ability of filled small bottles on site, the craftsmen proceeded to transfer argon from a standard bottle to an empty small bottle stored in the authorized rack of the Site' Services Fab Shop.
This activity had the approval of the General Foreman and Superintendent, and i interviews revealed that the men were under the belief that such a gas transfer violated no-requirements, with their major concern being the safety of bottle transportation to the work area.
Upon initiation of weldment, porosity was noticed by the welder in the roo+. pass and corrective action was initiated to determine the cause.
Another welder working on the aojacent half-coupling experienced similar result: so test passes were performed on a scrap piece of angle iron to determine if the porcsity was the result of fit-up contamination, the TIG torch or argon purge. When it was determined that the porosity was due to either the TIS torch or argon purge the men returned to the Fab Shop where , it was revealed that contaminants in the argon caused the porosity. As a result,. a decision to carry a standard argon bottle of knowe purity down , c'
i o Sy,h., ' ,.. E ~ m to the work area was implemented and the exieting root passe's were removed i to sound metal and visually inspected.
New.. lf-couplings were obtained and the resulting weldments were acceptable to applicable examinations.
Based on the'above, the licensee determined that: Although unable to certify argon purity. the Site Services - Superintendent, General Foreman and Craftsmen believed _they were transferring supplier's argon to a clean (small) bottle.
Interviews l of involved personnel revealed that this was the first known attempt i of argon transfer performed by other than the gas supplier with the.
Craftsmen's major concern being compatible working pressures of the cylinders.
] Upon recognition of weldment porosity, the Craftsmen stopped work and
- proceeded to determine the cause and corrective action.
R After the cause was identified, rework, including removal of the - , existing root passes'and rewelding using new fittings with a purge of-i know purity was performed.
I In process and final visual examinations demonstrated compliance to - site specifications for line classification (Non "Q"), and the actions of the welders by stopping work at porosity-identification shows commitment to quality- -
To preclude recurrence, written notification of this event has been delivered to the' craft Business Agent (for incorporation into apprentice i training), the Bechtel Welding Engineer _ (for incorporation into welder l orientation) and to all Site Services employees (emphasizing the limits i regarding compressed gas use and supply).
In addit %n, all small com- ' pressed gas cylinders on-site are being inventoried for return to the ' project supplier for authorized refill.
, Although this was a valid allegation, the inspector noted it was called to the NRC's attention after the welds were satisfactorily repaired and the licensee had taken action to adequately resolve potential problems i associated with transferring welc;ing gases to smaller bottles. The ! irspects has no further questions regarding-this incident or the ~ , licensee's corrective actions.
This allegation is closed.
! 10.0 Meetings with Licorsee (40500) ] Two mee'.ings were held, on site, during this report period.
a.
Nuclear Engineering Department (NED) Technical Support of Limerick Generating Station.
) l
, a
- ' ' + l, .e.
.. .
. On September 27,.1989, a " Root Cause Analysis Task Force" draft report was preserited to the NRC delineating the findings of a task force that had analyzed the NED support for Limerick. The presentation was , made to provide information on the current status of problem areas ' ' previously identified by the NRC. Discussions with the management, present at the meeting, confirmed that the recommendations are under advisement and that actions are in progress or will be taken when the report findings are analyzed. A list of attendees and the handout-provided at this meeting are included as Attachment A to this report, b.
Power Ascension Self-Assessment Program Evaluation.
On October 6, 1989, a Self-Assessment of the power ascension program was presented to the NRC. The NRC remarked that the program to date was going very well and, based on the assessment, felt that there was a' sound and well managed and dedicated group of people involved in the Unit 2 Start-up.
However, a word of caution was issued concerning complacency when things seem to be going well.
The licensee acknow-- ledged the fact and expressed their own-concern in that area with a resolve to pay close attention to the Unit Start-up. A list of attendees and the handout provided at this metting are included as Attachment B to this report.
11.0 Exit Interview (30703) The NRC resident inspector's discussed the issues in this report with the licensee throughout the' inspection period, ard summarized the findings at an exit meeting held'with the site Vice President, Mr. G. M. Leitch and the plant' manager, Mr. M. J. McCormick, Jr. on October 13, 1989.
No written inspection material was provided to licensee representatives during the inspection period.
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, ., . , Attachment A Engineering Meeting, September 27, 1989 Attendance List.
PECo , G. M. Leitch- ' Vice President, Limerick' ! . M.'J. McCormick Limerick Plant Manager . - L. B. Pyrih Manager Nuclear Engineering PEco Taskforce Members-F.'J. Coyle Chairman, Nuclear, Engineering Department . .. 'W. J.'Brady Nuclear Engineering Department
- .
A~, D. Dycus' NQA, LGS - ISEG , L. N. Ferrero Nuclear Quality Assurance . ! LR M.:Krich Nuclear Service Department
- !
'
- W. A. Texter Limerick Generating Station NRC
~L. Doerflein Chief, Section 28 LT.- Kenny-Senior Resident Inspector - . i L. Scholl' Resident Inspector = I M.. Evans Resident Inspector
- i I f Y . . . . J
. . ., - - - - - -- .. - -
- ,.
. . s - - . .
. . .
- . .. . NED Technical Support of LGS =
. ' ROOT CAUSE ANALYSIS TASK-FORCE - , e
., t . . Draft Report ' . Summary Presentation ' . i . ! ,
.
i . September 26,1989 ' . ,! i . , __ .- , - _ ,- - . ... . . . . . .
_ , , . - - - - - - - - - - - - - - - - - - ..
.. I ' - - ..._ D si - . . . L Purpose of Task Force . ' %
.
i
. . -, i .
To: identify the' root causes of the NRC's concern i regarding weaknesses in NED's ability to support
'
LGS.
'
[
i i I i .l ...
i l . l- - 1.
- - > ! ., - - . - .. ~ . . -.- ..
. _. . . . . . - .: . . Task Force Members F. J. Coyle - Chairman Nucm.;r..: rcu-ing Dept.
' ? ing Dept.
W. J. Brady Nucies '- A. D. Dycus NCs, abo
- EF L. N. Ferrero Nucleer Q.. 3
isurance . R. M. Krich Nucienr 3, vico Department i W. A. Texter Lin t ~ v Janerai..ig Station l 2, - - . - . u--. - , -. - -. . . . .. .... .
- m.
- - - .. . . ' a _ 3, -. - Methodology - . d e l 1.
Analyzed individual cases of deficient NED
support.
2.
Performed a-preliminary integrated analysis - using results of the individual cases and n the experience of the task force members.
! l 3.
Discussed preliminary analysis with various-i Nuclear. Group managers.
4.
Revisited the preliminary root cause analysis considering the managers'- input.
3.
l l ' \\ . . -. - - .
. _ _ _ _ _ _ _ - _ _ _ _ _... _ _ _ _ _ ._.
_ _. __ ____ _ _ _ _ _ _ _. _ -___ _.
._ z '- .,;c y D _ . ~. k $ - .. " - . . Cases .
Appendix R design requirements SALP, page_27 . invalid EQ certifications SALP, page 28 Large # of open TCAs SALP, page. 28 . Chlorine detector problems-SALP, page 28 . Flow switch qualifications 88-20, pages '4,' 12 i Fire access doors reportability 88-20, pages 3,13 , CREFES'hi-rad isolations 88-22, page 7 , ! ESW corrosion Maint. Insp. Rpt.,11-16 '
Control room purge selected by task force
l , Agastat relays selected by task force Domestic water-selected oy task force t-4 , ' b , r~~ 3 x e ,yr-
, #v r~.w.y e.
, awv, -s__, ,. _ _ _ _ _. _ _ _ _ _ _ _ _ - _ _ _ _____.__... a - ,
. . - ~ ,
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> . , . . . ., Findings a i !
. Management has not developed a mutual understanding i
of the Nuclear Group: values,.nor of how these. values
should be applied to the conduct of business.
-,
- i ~ In turn, managers have not disseminated these
values downward through the organization to the working level.
These conditions are not limited to NED and LGS
but apply to the-Nuclear Group as a whole.
., ' 5.
! _ , . _ _ _ . - . . . - ... - . .
- ----- ------- - -- ----.
,
- .
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. Findings-(cont.)
Root Causes/ Contributing Factors
1.
Workload / Lack of a Nuclear' Group prioritization system , 2.
Lack of an effective system for tracking engineering ' ! support tasks ' i
3. NED's lack of appreciation of the station's needs i ! 4.
Less than adequate teamwork between NED and LGS ' t
< l 5. Failure of both NED and LGS managers to establish
clear, mutual expectations
s 6.
l ? ! -. _. _ .. _ _ - _ , _, _ . . - _ _ _ _._ ___,_,
~ - -~ ~ - - - -- ,. ~ y_g . , , -_ .. - i . -. _
- .
'.. ... Findings f(cont.)- Root Causes/ Contributing Factors , L l.
6.
Less than adequate communications.between NED j and LGS
7.
Less than adequate reportability procedures n 8.
Less than adequate supervision and-management of NED activities L
9.
Less than adequate " operations focus" by NED on technical matters i 10.
Reorganization U 7.
, _ _ _ _ _ _ - . - " ' ~ ~ * w - 4.ss' .,,. * .<*%e=A_y
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-- -- . _ _a . . , ,- .. g
- ,.
- ' -. _ . x
. ~ . [ Findings (cont.)
. '
i
2.
No. EWR~ system- - ' '6.
Inadequate communications j 3.
Inadequate reportability procedures t
- -
1.
Workload /No prioritization system 8.
Inadequate supervision ar.d management 9. Inadequate ope.'ations focus ' 10.
Reorganization - i < . ii 3.
Inadequate. appreciation of station's needs - i i -- , l 4.
Inadequate teamwork- - . 5. Lack of mutual expectations a
8.
..: ,-i =. __ ._ _ .., _ .. .. __ -
- - - . x _ . , , - -- . . .,
- - .- . . Findings (cont.)
.
-, a i !
- Management has not developed a niutual understanding
- of the Nuclear Group values, nor of how these values-should be applied to the conduct -of-business.
. i .' , ' - * In turn, managers have not disseminated these
values downward through the organization to
the working level.
!
, !
- These conditions are not limited to NED and LGS.
I
but apply Lto the Nuclear Group. as a -whole.
- !
. a - i 9.
i __ _ _ . ~ ._ . ~ ~ - . . .. . - -.
-.
- -
- - - - - g.
- - ,, .., -_
- .;.
_ .: ' -- J Recommendations
. +
- Recommendations. included in the report are.not.
comprehensive; they are only representative ac00ns , to be considered in developing an improvement plan'- ! A NUCLEAR GROUP lMPROVEMENT PLAN.
l A = Although each recommendation is noted as being ' associated with one of the ten root-causes, they
are,.in the aggregate, directed towards fostering
, the mutual understanding of the Nuclear Group values.
. 10.
. . -- . . . . . _- - . . - - -
.- .- , ... ' " \\ Q ' ' . . .. Recommendations -(cont.). Example Recommendations , i Be sensitive to verbalizing negative perspectives
of other departments.
(4.2) - f Deal with conflict - jointly review quotes of Appendix
l "C".
(4.6) Develop common goals through the mutually agreed upon
. i balancing of budget constraints, quality, customer
satisfaction, excellence and,.the tools needed to' ~ , improve future-work processes. (5.1)
! L , l l l . i ' 11.
! , H . - r . -.. - _ _ __, .. . . . .
_ --- - ..
. - .. - .; i Recommendations (cont.)
~ . Example Recommendations .
- Develop an interface. agreement which defines.the
' ! organizational roles, expectations and, support required to attain the common goals. (4.1) ' l
- Disseminate the mutually agreed upon values and i
i goals DOWNWARD through'the organization.
-
i
- Coordinate the many departmental improvement pians
through the formation of a Nuclear Group plan which umbrellas the departmental plans. (5.3)
- Establish a steering committee of division level
managers to coordinate: the Nuclear Group improvement plan. (5.2)
i !
12.
. - . . .... . . - -- -. - - - - - - - - - - - - - - --- i '
. _ - . - " --
- - -.. ' ! . ~ ' Conclusion ~ . . , ! - i ! Resolution of1the issues identified by the task force
requires the' application of-values.
By jointly resolving . L these issues, Nuclear Group management should develop l a mutually agreed upon concept of what the Nuclear .; Group. values mean and, a mutual agreement on how these j o l values should be applied in the normal conduct of ' l business.
- ! l , i 13.
l .
- -
.,, , - , , .- .. - ... .
! $.+ . , I %.- ,$ q,7, ;..._ s , e, . > pm. ' *' , j-Attachment B < , V; . LGS Unit 2 Power Ascension Self Assessment October 5. 1989 Attendees , P Co i: C..McNeil Executive Vice President, Nuclear 'G.-Leitch Vice President, Limerick Generating-St.stion (LGS) > ' M. McCormick, Jr.
- Plant. Manager J. Doering' Operations-Superintendent ,, J. Kemper. Senior Vice President, Nuclear Construction T. Ullrich-Manager, LGS Projects J. Corcoran Startup. Superintendent < R. Hurd Power Ascension Support >
- P. Duca, Jr.
Technical Superintendent C. Endriss Regulatory Engineer L. Pyrih Manager Engineering . W. Alden-Staff Engineer Ri.Dubiel: Plant Services Superintendent .J.
Spencer' Maintenance /I&C Superintendent G.-Edwards-Operations ' R. Ballou - Power Ascension (General Electric) D.:Shaner . Licensing
- E. Grant Licensing R. Krich-Licensing
' W. Dagan NSSS Test Supervisor (General Electric) 'J. Klucarf Startup Operations F. Pennell, Jr.
Limerick Information Center C. Dry Limerick Information Center Commonwealth of Pennsylvania
A. Bhattacharyya Nuclear Engineering NRC
T.~ Kenny Senior Resident Inspector W. Kane Director, Division of Reactor Projects (DRP) L..Doerflein Section Chief, DRP M.-Evans. Resident Inspector
- L. Scholl Resident. Inspector
$ . d .
_
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LIMERICK. GENERATING STATION - I POWER A.SCENSION SELF-ASSESSMENT PROGRAM l EVALUATION AREAS ! <
- ADEQUACY OF THE-UNIT 2 AND COMMON SYSTEMS FOR~ SAFE AND j i RELIABLE OPERATION j ! - CONTROL ROOM OPERATIONS AND PROFESSIONAUSM
) - TEAMWORK AND COMMUNICATIONS ! a - ENGINEERING AND MAINTENANCE SUPPORT SERVICES-
l ! ! - ORGANIZATIONAL INTERFACES, INVOLVING BOTH ONSITE AND j l OFFSITE GROUPS j
- l
PLANT CONFIGURATION CONTROL
- l
- d ! PR EDURAL AD UACY AND EFFECTIVENESS OF -
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. . LIMERICK UNIT NO. 2 POWER ASCENSION SELF-ASSESSMENT PROGRAM l AST4SSafENT AT COMPUETION CONTINUOUSACTMi1ES BNWEENLY - 0F TESTNG PMMIES ' pg mm 1.
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LO9VP00FER TESTMG pgng y,y co gmer rM p 2.
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l py . ADOfT)0Nel EVENT I MANAGEMENT \\ MM ^ - REPORTS f \\ SElf l^ j M ' l .1SSESSMENT 'I / REQUIRED e SYSTEMSI '~ ' ) / STAWS _ f y.
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nieNeGEn0ENT a
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, , INCINEERING GR0t/P , Pavomesenct l -
- G4 f AssEssu wT l
AssEssn0ENT SU*****Y Ul*END , N i l' i misemens l l:
- m *'"*
L I NN. I i messmewr f " o u , _ -. -. . - -... -. - _....- - - - - -. - .. - . -,. - - - - - -. _.. - -.. - - - _. _ - _ - - .
. - '
-
i STRENGTHS F h-y l ~ j
- PROFESSIONALISM THROUGHOUT LGS ORGANIZATION ! l ! ~ - RESOLUTION OF EQUIPMENT AND SYSTEM PROBLEMS ,
l ! - USE OF PROCEDURES ! j - QUALITY MAIN CONTROL ROOM OPERATIONS j i . - EARLY IDENTIFICATION OF PROBLEMS AND PROMPT
- <
ACTION I
. . . i 1.
. - . _.. _ - . _.. __ .... . .J .
- . . . .. . . . WATCH AREAS RESOLVED !
- PLANT INCIDENTS INVOLVING PERSONNEL. ERRORS
- o
- NUMBER OF: TEMPORARY PROCEDURE CHANGES
- BACKLOG OF ENGINEERING WORK REQUESTS i
!
- PLANT CONTAMINATION REPORTS (
'
1 .i
i 10/06/89 i I - - - - - - - - -. . . . . .- .. : .-. -- -. -. -.
- - - -- - - - - - - - - - - - - - - - _ - _ - _ - . .$ - WATCH AREAS OPEN
- : BACKLOG OF CORRECTIVE MAINTENANCE REQUESTS
. MISCOMMUNICATIONS BETWEEN PERSONNEL . 10/06/89 . - - - - . = .. -.- -_ _ - - _ _ __- ,
., .@ $)
- ' E h>
,,,,gf 9b, IMAGE EVALUATION gpff
j;0(9 V: y TEST TARGET (MT-3) 44? /'4 4+/ %,;%ge l.0 lt M Baa [[f BL23-i,i [' Ne 1.8 1.25 1.4 1.6
150mm >
6" > 4}#y %y,, /;;g //// '4 g ,y,,,,, 48g - . . hp, +qr C Q_;;, _ . . ; J--l s
- - - - - - - -. -, - - - - - _ ss> (# 4> //o % @*< \\a\\#, ////gf [W,,4,# ' IMAGE EVALUATION N//7 % %f// TEST TARGET (MT-3)
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p,,,9 ,, 1.0 F: 2 EM i u2 p" b tu l.1 b" EE I.8 1.25 1.4 1.6 .
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IMAGE EVALUATION Akt ////pyy 0 @g/g 4)y,y: 9/ TEST TARGET (MT-3) j %p/ %,k l.O IBM M E m In'-=z m m l-l $M b=3 t: 1.25 1.4 1.6 .
150mm >
6" > <>+;k //%g,r/< - /!b sp>;<p/// ,,p# - - - <+4*r . o t i; % . %
-- , , & 4cb 4
/ ',$e @9 % //,jg % [ d' hg, / s IMAGE EVALUATION x\\f//77%! $/ TEST TARGET (MT-3) f g+/ %,g% l.0 !!We m
- ll El I.I I" EE i
1.8
1.25 1.4 1.6
150mm >
6'~ > .gqgy.4 %y,,,,,,,- - / 4 /////;% ,48 , -- si,t.
y
-' ,A:-
I = 4 -
. -
- e ~
. *- _ w .. ' ., .' , STARTUP TEST PROGRAM OVERVIEW SCHEDULE PROGRESS THROUGH 10/3/99 .i ! ! ! - i i i i e i.
s START ruEL [0A0 6/;23 A i e ' ' ChPLT FUd. LOAD 7/A A OPEN 6 , ' $NITIAL CRITICAlfTh (8/12 A) ' i i ' i.
_ RAik0 TEMPfPRESS.hEACHED (8/18 h) e .
,
HEATUP . e ' - e .i (XCEED SK (8/28.A) e- ', Rold TUR9tMk (8/30')) ' . . SYMCHRohflZE CEM. (9/ t A) I . . TC.#1
- REACH $5^504 (' /13 A)
p
, LOSS [Or OFFSITE PowtR SCRAW (9/18 A) l SHUTOOwM OUTSr0E CONTROL
ROOM SCRAu (9/25 A) tcaz j , e t
' s
1 gg gg ' E PowtR (THERMAL) -- 100 ' --
_
I p e -- 80 I N e --
l T/G RUMBACY --
h ! { --
T/G RUNBACK % , -- A0, . !
- - 30 2 i.
l -- 20 = r . --
- w
, --
.......................................................,...................,.............................!...,............,.....
25
9
23
6
20
3
17
1
15
JUNE l JULY l AUGUST l SEPTEMBER-l OCTOBER 1989 , _.
.__ _ ...o
_ _ _ _ _ _ _ _ _ - _ _ _ - _ _ _ _ _. _ _ _ _ _ _. _- _ _ _ _ _ _ - _ .__,
- -
.... A - ... GROSS MWe ELECTRICAL GENERATION 6/22/89 THROUGH 9/30/89 - ' i i UNIT (1 F.W! COPPER STABILIZATION , -- 1100 !/ N i. - _ , - % .-- 1000 ,l-- 900 , . ,
e . -- 800 ? . . DECREASE IN. ' -- 700 HIGil CIRC. WATER CONDENSER , -- 600 TEMPERATURES VACUUM
~~ 00 DECREASE.IN e'. - , CONDENSER VACUUM -- 400 DUE TO BLOCKING ERitOR '
- CDNTROLj ROD PATTERN ADJUST!MENTS i
-- 300 -- 200 -- 100
-- 1100 i -- 1000 f- - 900 3-- 800 . S/D OUTSIDE ' CONTROL ROOM SCRAM -- 700 LOSS OF OF SITE PI)WER S RAW. i-- 500 ~~ - - - i T/G RUNBACK -- 400 i-- 300-k -- 200 - 100
- -
,
i... ................................,...................,............,......,............,......,.............,............
25
9
23
6
20
3 to
24
8
22 JUNE l JULY l AUGUST l SEPTEMBER l OCTOBER 1989 ._ _.. _ _ __.____._____ __ _ ._ _
.. . , c '^ ~ -' ;3
~ ' ' - LIMERICK UNIT 2 ' l . POWER ASCENSION SUMMARY THROUGH TC-2- . '! COMPLETED STP's a TEST CONDITION NO. OF TESTS
q
, ' OPEN VESSEL
i , [ i HEATUP
-, . i TC-1
!
TC-2
' ., .4 TOTAL 110
!
! I i j u t ' t i
.,anancm a i ! ? t l '
! I ' f ,
' ! ' ' i a "m - "* w
a a -
=. x..: a ---. - -w-. - --a.---u , s .. ~.n.a a--.e -. - -
.-, . . .. - .. . LIMERICK UNIT 2 - POWER ASCENSION PROGRAM - . TEST CONDITION - OPEN VESSEL > !
- ENSURE ADEQUATE CORE SHUTDOWN MARGIN DURING FUEL
LOADING ij - COMPLETE FUEL LOADING
. - CONFIRM OPERATION OF THE CONTROL ROD SYSTEM VIA , l lNDIVIDUAL ROD FRICTION AND SCRAM TESTING
l - OPERATIONAL HYDRO > i
i .,_,- l l
, .
-., .. _.. _- -, . _ _. - ..,., , ,sw.
,,;..
. .g' di '" .0 - , , . , ! LIMERICK UNIT 2 - POWER ASCENSION: PROGRAM i t TEST CONDITION - HEATUP
i i - NUCLEAR INSTRUMENTATION OPERATION ,
l - HPCI AND RCIC OPERATION l <
! ., ! - PROPER PIPE EXPANSION i r . - PROPER OPERATION OF HVAC SYSTEMS [ - OPERATION OF THE CONTROL ROD SYSTEM i t ! - PROPER OPERATION OF REACTOR VESSEL WATER LEVEL j l INSTRUMENTATION l - PROPER RADIATION ZONING l - PRESSURE REGULATOR CONTROL OF REACTOR PRESSURE
! - IN;TIAL OPERATION OF REACTOR FEED PUMPS - PLANT MONITORING SYSTEM (PMS) OPERATION " ,_ ' _. _... _, _ _ _ -. .. - - _ _ ... . .. _ -
.
- ..A"
b.
. . . .
. ' l LIMERICK UNIT.2 - POWER ASCENSION PROGRAM ' TEST CONDITION - #1 ! i i ! ! CONFIRM PROPER OPERATION OF FEEDWATER STARTUP LEVEL i - ! CONTROL l i i
' l INITIAL ROLL OF MA!N TURBINE / GENERATOR AND -
SYNCHRONIZATION TO GRID i
i CONFIRM OFFGAS SYSTEM OPERATION - i RCIC COLD QUICK START WITH REACTOR VESSEL INJECTION - i ! INITIAL OPPORTUNITY TO OBSERVE ABILITY TO MAINTAIN - l ACCEPTABLE FEEDWATER CHEMISTRY j
i
.,
-cm
i
.- , , . .. - - - . - = - -
v _ . . . . -. , ( . l l i LIMERICK UNIT 2 - POWER ASCENSION PROGRAM ! TEST CONDITION - #2 e
- PLANT MONITORING SYSTEM DYNAMIC SYSTEM TEST CASE l CORE PERFORMANCE CALCULATIONS o l ' - CONFIRM STEADY STATE AND DYNAMIC PIPING LEVELS l ! - CONFIRM PROPER OPERATION OF FEEDWATER SYSTEM
- CONFIRM PRESSURE. REGULATOR OPERATION j t - CONFIRM PROPER OPERATION OF SAFETY RELIEF VALVES j
- DEMONSTRATE SHUTDOWN OF PLANT FROM REMOTE SHUTDOWN l PANEL - DEMONSTRATE PLANT RESPONSE TO TURBINE TRIP AND LOSS OF - OFFSITE POWER .
! ' - . .- -- .. - - - - - - - - - - -- -- - n --
- . ' - .. -'e.
A..' ! ! { . 1
! ! LEVEL 1 TEST EXCEPTION REPORTS j l TC-OV THROUGH TC-2 ! LEVEL 1 CRITERIA FAILURES.(CLOSED) - 3
- ! - REACTOR ENCLOSURE COOLING WATER pH GREATER THAN CRITERIA IN TC OPEN VESSEL. ACCEPTED AS IS. G.E. WATER QUALITY ! SPECIFICATION UNNECESSARILY RESTRICTIVE. NO FUTHER FAILURES HAVE OCCURRED.
- RCIC FAILED TIME TO RATED FLOW CRITERIA IN TC HEATUP. TEST WAS ' NOT PERFORMED PROPERLY. RETEST WAS SUCCESSFUL ! - MAIN STEAM LINE STEADY STATE VIBRATION EXCEEDED THE CRITERIA IN l ~ TC-2. VIBRATION ANALYZED' AS ACCEPTABLE. CRITERIA WAS ! UNNECESSARILY RESTRICTIVE AND HAS BEEN CHANGED.
, ,- on . eir _ - -2..t .-._.u_... _ a - _.J..___ ..m .._.__,. % e -%m ..-_ --.m,-_, _m _ _.m_
.
.. _
- o-
. . ' .
- STARTUP TEST PROGRAM OVEfWIEW SCHEDULE
' STATUS AS OF 1984WD , e.
l 8! i l ' < . STAR,7 rdEt (Oa0 6/23 A l! l.' REACH 1005 CORE FLO4d (11/94 S) (td/ f f F); I
curLT r'Uttit040 7/4 A e: ! ~ ! + i l 1 8, j ,
- I !- OPEN VESSEL Ml t 'i TC #3 I e t ' I i i ! ,, . ' 's! t ! , 8} j ! entiat C#ncAtiiv (s/s s)(e/t2 4') REACH i0cm P0wtR ( 2/2 s) j
,, , 4 - . RAtt0 Ttur./y. sS. # TACH (O (8/10 $)(S/18 A) usiv sCRaw (t/s2 s)
- i
- . i t ' l t
f-TUR9tNE TRIP SCRAM (t/21 $) . HEMUP M 'I . ' / . lt TC es.4.s i i . . ' e' , . ei . . txCtt0 su (t/ s s) (s/2s A) ,
- 0tt TN (,/5 s) (e/30 A)
i i , { svwCHR0nizE Otu. (s/s4 s) (9/ A) M,! O (1/27 to $/f,5)
,
- l TC'#1
- ' l
,
. I i
.
y . , j CH 45-50s (10/7 5) (9/13 A) i
f LOSS OF OFF$tTE PowtR SCit4W (30/20,S) (9/I8 A) e, ' e-t SMUTOOWu OUTSIDE ,ROL #00W SCRAM (10/27 $)(9/25 A)
3g { TC ! l 2 P0wtR (THERMAL) . ij J-100 l - i !! . + ' 1Ut . , ' - 90,
. l !
!
i ! i - 80 I ' i , - ,. I ,f -- 50 I , 8l ! I l ' ' '
+ i . i j j -- 40 { ' , !
! i-30. ,
i
' ! ' i , i L-20 * ' ' ! ' h h ' '
d' J j _ .r ' t i- 0 ' r-i - .,. _,., ....,.,.,, ., ,.,,., _,,.,.,,,., . , _,, ,., _., , 4 11 18 25 2 9 16 23 30 6 132027 3 to 17 22 1 8 15 22 29 5 1219263. 10 17 24 31 7 14 21 28 4 11 . ' JUNE l JULY l AUGUST l SEPTEMBER l OCTOBER l MOVEW9ER l DECEW9ER JANUARY l FEBRUARY-l 1989 1990 ' PAOWER t D#W a -- y , , ,,., v w-- - ,.,.s..~y a y, -g ,,.,,-
e ' - ~ y =,. - ' ~- .., __
, -
- -
A:
-Q: - LEVEL.2 TEST EXCEPTION REPORTS ! TC-OV THROUGH TC-2
LEVEL 2 CRITERIA FAILURES - 13 l ANALYZED AND CLOSED - 11 i i - PIPING / EQUIPMENT VIBRATION & PlPE EXPANSION '
!' - SRV TAILPIPE HIGH TEMPERATURE - RCIC CONTROL SYSTEM RESPONSE: DECAY RATIO
! ! - HPCI SPEED RESPONSE ! i l SUBSEQUENT ACTION PLANNED - 2 l - FEEDWATER CHEMISTRY, DISSOLVED OXYGEN BELOW SPECIFICATION; TO BE RESOLVED BY INSTALLATION OF A FEEDWATER OXYGEN INJECTION SYSTEM.
- FEEDWATER TURBINE RESPONSE TIME; RESOLVE THROUGH FURTHER FEEDWATER TUNING IN TC-3.
,a c., .. ~... -- ~.._c.
, c.. _.;_____________________.__________________ m.... . m _ _,, _ _.. _ _ _ ____ _ _.., __.. .. , , _
.. - _.. _. .... _.. _ _ _ _ . _. - _ _. _ _ _ _ _ _.. _ _. _.. _. .. _. _ -. . -.. ~ ~.. _ _ _ _ _ _ ._ ,
- ',.
- .. i . . . r . . . .. i 110 O > A.
96ATURAL CIRCu(AT30eg s.
neweessues Rec RoutATen puesp sesso l too - gD C.
AseALYTICAL LOuutR utstT Op , teASTER POuuta pleur MOL . -i - ' . 0.
AssALv?H:AL uppgR unsef " OF GSASTER pouvaR PLour 80 " /[ , ' , /p/ = ~ / - ,.. i
-[ g(/ M/ ft g . - . .. ,, , . . ..,
. , . M E m essenesues posugR usse 30 = fvPtCAL STARTuo paTM, ' TC1 . CAVITATI0st m.0 ,7' ,. . . ___ ' '
8 ' ' ' ' -0
10
m e a e a g g gg 110 99RCE9tT CORE FLQ90 .. _... -_. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _ _ _ _. _ _. _. _ _..... _ _ _ _ _ _ _. _...... _ - _.. _ - -.. _,
i.
- ... - . - ! . -l
- -
a , .. i ! LIMERICK UNIT 2 - POWER ASCENSION PROGRAM ! l TEST CONDITION - #3 l , i.
, i - DEMONSTRATE PROPER OPERATION OF RECIRCULATION FLOW ! CONTROL SYSTEM
a ! - DEMONSTRATE HPCI INJECTION TO REACTOR VESSEL ! l - ! - ADDITIONAL DEMONSTRATION OF OPERATION OF FEEDWATER
i SYSTEM AND FEEDWATER LEVEL CONTROL i
! l l - DEMONSTRATE PLANT RESPONSE TO SINGLE AND DOUBLE l l RECIRCULATION PUMP TRIPS l l - APRM CALIBRATION , - DEMONSTRATE JET PUMP OPERABILITY
i 89100804 CMT l . . - . . .. - .._.; ..
- - - - - - -- - - --- - -
- - - - _ _ - _ y ..
.. j . ;; F " .. .i
LIMERICK l UNIT 2 - POWER ASCENSION PROGRAM
! TEST CONDITION - #5 .
. ! - HIGH POWER APRM CALIBRATION I! l a i t j - PLANT MONITORING SYSTEM CORE PERFORMANCE-CALCULATIONS i ! j - DEMONSTRATE PRESSURE REGULATOR RESPONSE TO
! CONTROL / BYPASS VALVE OPERATION i
i-i l - DEMONSTRATE FEEDWATER / FEEDWATER. LEVEL CONTROL OPERATION j l ! i t
t t i ! ! i ! 'l l
i ! ex.cm
i i ! ,
s I > ' - , ,a., -., . _.,_
- - ..
1 o i - , ,9. ' ' ! ] LIMERICK UNIT 2 - POWER ASCENSION PROGRAM-
! TEST CONDITION - #4 o
( .. l - DEMONSTRATE PLANT RESPONSE FOLLOWING TRIP OF BOTH , l REC!RCULATION PUMPS i ! l - DEMONSTRATE RECIRCULATION SYSTEM PERFORMANCE ! i l .i ! - DEMONSTRATE PLANT MONITORING SYSTEM CORE PERFORMANCE ' ! - DEMONSTRATE PLANT RESPONSE TO RESTART OF RECIRCULATION . PUMPS ! !
.; ' i l - !
' .
f '! ! - cm , - i > .. . - - - - - --. . .
, . [ "; > y . ..- ,., .
! LIMERICK UNIT 2 - POWER ASCENSION PROGRAM l { TEST CONDITION - #6 j
. I i - CONFIRM RECIRCULATION FLOW CONTROL OPERATION o ! i ! ' l - CONFIRM FEEDWATER / FEEDWATER LEVEL CONTROL OPERATION i i ! ! ! - DEMONSTRATE PLANT RESPONSE TO FEEDPUMP TRIP l l
i ! ! - DEMONSTRATE PLANT RESPONSE TO TURBINE TRIP l l l - DEMONSTRATE PLANT RESPONSE TO FULL MSIV ISOLATION l l l l - CONFIRM PRESSURE REGULATOR OPERATION i ! ! ! I i f suoiocHT ! i .. ; ! I ' _ , . ,- _ ..
, ..
. ~= c.. ^' .) , . g e e.
u $~ .. r
LGS #2 POWER ASCENSION PERCENT COMPLETE comma.mumma 100 _ . I
WARRANTY ' ! ,e l RUN _
_ ,. ,i'
_ ' - -- - - - - - - -, -. - - - - - - - - - - - - - - - - - -- v- - ---
," . - c -/. ~~~ TC 6
gQ .. ........ .,#.. -...... f**...... ., _... = , .
,e TC 4 = '
,o - TC 5 -
5---- -- -- -- --- - ,# - ---
- l
- ' - - -
- - - - - - - - - - - . g-g--- w
.~-~ F
, w
--*.-- , - ~ - '.
- --
-- --- -- ' .- L- - - - - - - - - - ~ n
,. /* l <
- ~
O
- O
-
- TC 2 \\
1 -- --- - - -l-
- < "
- - n =
i Z i .*
' ' w
- --*
_ t ,
40 2-- r- ./ -- -- -- gr
s . TC 1 w
.' - o_
,s
- .. <
- _ ,.....#... ..f * }... ... ~.. _ ' TC HEATUP
, f _
20 :- - 'g... - -
. i o* l,
- e ' "> - - - - - - - -
TC OPEN VESSEL - . - ' =
... ' i
- '
_
gi nu ign....;. -- ;= =. ,g...... ;,.gg.,..;, q,.....p.m,;,...,g..,...g.,.. g--..g :.., ,g...,7...,..,,g....po...,.....,....p u...g.,,,,,p ..p..... : x,,...p....p m.,g.....,,,,,,,g...n.g,. ..g..m.p ru.g - 4 11 1825 2 9 16 23 30 6 13 20 27 3 to 17 24 1 8 15 22 29.5 12 19 26 3 to 17 24 31 7 14 21 28 4 11 i JUNE l JULY l AUGUST l SEPTEMBER l OCTOBER l NOVEMBER l DECEMBER JA NUARY l FEBRUARY l 1989 1990 l ACTUAL TARGET SCHEDULE ________.
. i , I 59.75 65.45 42.8% , ! ! - . , . . - - - .. -- . - - - - . . .
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _. _. - -. _ _ _. _., _ __ __. . g
.,
9.
- STARTUP TEST PROGRAM OVERVIEW SCHEDULE CURRENT FORECAST AS OF 10280 ' I
. ! . 221 OtJTAGE , ! , , , i - . - REACH 1005 CORE FLOW (10/19 F). , . . s
i . ' - REACH 1005 POWER (l t/' 6 F)I gg j y i . i MSIV SCRAW (1 t/29 F) l TURB,ME kRIP SCRAM (12/9 F) . i
o.4.. - . i . .* . I . , , 222 m1TAGE 1 i . ' ' . . . s
cmu.noin.
i s . > , . ! . . l .-. t j o.+,. 2ei S) t . - - ,. .. i 5 P0wtR (Tl4ERMAl)
8 -- 100 !-
m g l . g -- !-- e0 y -- 70 g ! , ~
- --
60 $ . ' i-- 50 [ ' i-- 40 y . i-- 30 E.
l i- - 20 * j _ j - )
- --
,0 . ! . i--
.................,...........................,.........................,,..................................................
8 15. 22 29 5 12 19 26 3 10 17 24 31 7
21' 28 4
l OCTOBER l NOVEMBER l DECEMBER JANUARY - l FEBRUARY l 1989 1990 891003C M 8 .. _ - _... _ _ _. _.. _ _ _ _.1.
.. _ J.,., .a.
,., _., -. _ . _ }}